Downhole debris removal tool and methods of using same

ABSTRACT

A downhole tool for removing debris from a wellbore comprises a screen member, an incoming fluid accelerator, and a cavity for capturing debris. The incoming fluid accelerator is disposed above the screen and accelerates the flow of an incoming fluid through the accelerator and into a screen bore. The incoming fluid then exits the bottom of the tool, mixes with wellbore fluid containing debris to form a combination fluid that is transported upward within the wellbore annulus. A pressure differential between the incoming fluid flowing within the screen bore and the wellbore annulus pulls the combination fluid containing the debris into the cavity where the debris is captured. Fluid and/or debris not blocked by the screen flows through the screen into the screen bore to be circulated downward and out of the tool where it can pick up additional debris for capture.

BACKGROUND

1. Field of Invention

The invention is directed to a downhole clean-up tool or junk basket for use in oil and gas wells, and in particular, to a downhole clean-up tool that is capable of creating a pressure differential to transport debris from within the wellbore annulus through a screen where it can be collected by the tool.

2. Description of Art

Downhole tools for clean-up of debris in a wellbore are generally known and are referred to as “junk baskets.” In general, the junk baskets have a screen or other structure that catches debris as debris-laden fluid flows through the screen of the tool. Generally, this occurs because at a point in the flow path, the speed of the fluid carrying the debris decreases such that the junk or debris falls out of the flow path and into a basket or screen.

SUMMARY OF INVENTION

Broadly, downhole tools for clean-up of debris within a well comprise a screen member having a cavity disposed around the outer wall surface of the screen member. A fluid pumped downward through the tool travels through the bore of the screen member and out of the bottom of the tool. In so doing, a low pressure zone is created within the bore of screen member causing wellbore fluid to flow from the wellbore annulus and through the screen where it is circulated back down through the bore of the screen member and out the bottom of the tool. In so doing, debris carried in the wellbore fluid is trapped by the screen and collected in the cavity. Further, when the lower end of the tool is placed near the bottom of the wellbore, or near a collection of debris within the wellbore, the fluid exiting the bottom of the tool stirs up the debris so that it can be carried upward and into the cavity.

In certain embodiments, a single tool is disposed in a work string. In other embodiments, two or more tools are disposed in a work string, either adjacent each other or spaced apart, so that additional debris can be collected during a single trip into the wellbore.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a partial cross-sectional view of a specific embodiment of a downhole tool disclosed herein shown disposed in a wellbore.

FIG. 2 is partial cross-sectional view of the downhole tool shown in FIG. 1 taken along line 2-2.

FIG. 3 is a partial cross-sectional view of two of the downhole tools shown in FIG. 1 shown disposed adjacent each other as part of a work string.

FIG. 4 is a partial cross-sectional view of another specific embodiment of a downhole tool disclosed herein shown disposed in a wellbore.

FIG. 5 is a cross-sectional view of an additional specific embodiment of a downhole tool disclosed herein.

While the invention will be described in connection with the preferred embodiments, it will be understood that it is not intended to limit the invention to that embodiment. On the contrary, it is intended to cover all alternatives, modifications, and equivalents, as may be included within the spirit and scope of the invention as defined by the appended claims.

DETAILED DESCRIPTION OF INVENTION

Referring now to FIGS. 1-2, in one particular embodiment, downhole tool 20 is disposed within a wellbore or well 10 having casing 12 by running tool 20 into wellbore 10 on work or tool string 14 having tool string bore 16. In the embodiment of FIG. 1, downhole tool 20 comprises incoming fluid flow accelerator 30, screen member 40, and shroud 60.

Incoming fluid flow accelerator 30 facilitates increasing the velocity of an incoming fluid (not shown) flowing down tool string bore 16 in the direction of arrow 11 before entering screen member 40. As illustrated in FIG. 1, incoming fluid flow accelerator 30 comprises upper end 31, lower end 32, outer wall surface 33, and inner wall surface 34 defining bore 35. In the embodiment shown in FIG. 1, the shape and size of bore 35 causes the increase in velocity of the incoming fluid as it flows through bore 35 in the direction of arrow 11. In the particular embodiment of FIG. 1, incoming fluid flow accelerator bore 35 is a “step-down” bore meaning that the inner diameter of bore 35 progressively decreases at stepped intervals from upper end 31 toward lower end 32. Although bore 35 is shown as being a “step-down” bore, it is to be understood that bore 35 could have other shapes and sizes to facilitate increasing the velocity of the incoming fluid as it flows through bore 35 from upper end 31 toward lower end 32. For example, bore 35 could comprise an inverted-conical shape that decreases in inner diameter from upper end 31 toward lower end 32.

In the specific embodiment of FIGS. 1-2, screen member 40 is connected to incoming fluid flow accelerator 30. Although screen member 40 is shown in the embodiment of FIG. 1 as being connected directly to incoming fluid flow accelerator 30, it is to be understood that screen member 40 is not required to be connected directly to incoming fluid flow accelerator 30. To the contrary, one or more intermediate components may be disposed between incoming fluid flow accelerator 30 and screen member 40.

Screen member 40 comprises upper end 41, lower end 42, outer wall surface 43, inner wall surface 44 defining screen bore 45, upper inner diameter 46, and lower inner diameter 47. In the embodiment of FIGS. 1-2, upper inner diameter 46 is smaller than lower inner diameter 47. Apertures 48 place outer wall surface 43 in fluid communication with inner wall surface 44 and, thus screen bore 45, are disposed along a portion of inner and outer wall surfaces 43, 44. As shown in FIG. 1, no apertures 48 are disposed above the top of shroud 60; however, the location of apertures 48 is not required to be so limited. Instead, additional apertures can be disposed above the top of shroud 60. Apertures 48 can having any shape and size desired to allow fluid to flow through, yet small enough to prevent certain sized debris from flowing through. For example, apertures 48 can be circular or other shaped holes, slots, or comprise a wrapped screen that provides randomly shaped openings.

Shroud 60 comprises upper end 61, lower end 62, outer wall surface 63, and inner wall surface 64 defining shroud bore 65. Upper end 61 includes one or more openings 66. Upper end 61 may be completely opened, i.e., having a single opening 66 not having any portion of upper end 61 being attached to outer wall surface 43 of screen member 40. Alternatively, one or more portions of upper end 61 may be connected to outer wall surface 43 of screen member 40 to provide an increase in tensile and torque strength of tool 20. In such embodiments, one or more openings 66 may be disposed within upper end 61. For example, as illustrated in FIG. 2, upper end 61 includes a plurality of openings 66.

Outer and inner wall surfaces 63, 64 of shroud 60 do not include holes or apertures and lower end 62 is secured to outer wall surface 43 of screen member 40. Accordingly, cavity 68 is defined by outer wall surface 43 of screen and inner wall surface 63 of shroud 60. In the embodiment of FIGS. 1-2, shroud 60 is concentric with screen member 40. In addition, as shown in FIGS. 1-2, shroud 60 comprises a larger outer diameter compared to the outer diameter of screen member 40.

In operation, downhole tool 20 is placed in tool string 14 and lowered to the desired location within wellbore 10. An incoming fluid is then transported down bore 16 of tool string 14 and, thus, into bore 35 of incoming fluid flow accelerator 30. The velocity of the incoming fluid is increased as it exits lower end 32 of incoming fluid flow accelerator 30 in the direction of arrow 11 and enters screen bore 45 of screen member 40. Due to the velocity of the incoming fluid flowing through screen bore 45, a pressure differential is created across one or more of apertures 48 between the screen bore and wellbore annulus portion 19. As a result, fluid within wellbore annulus portion 19 is drawn toward screen member 45, and thus, into cavity 68 and through apertures 48.

The incoming fluid continues to flow downward through screen bore 45 until it exits lower end 42 of screen member 40 as indicated by arrow 13. Due to the increase in size of lower inner diameter 47, the incoming fluid velocity decreases before exiting lower end 42.

Upon exiting lower end 42, the incoming fluid mixes with wellbore fluid contained within wellbore 10. The wellbore fluid includes one or more pieces of debris. The mixture of the incoming fluid and the wellbore fluid is referred to herein as the “combination fluid.” The combination fluid is carried upward within wellbore 10 in the direction of arrows 15. As a result, debris that is desired to be captured by tool 20 is carried upward. Upon reaching upper end 61 of shroud 60, the pressure differential between screen bore 45 and wellbore annulus portion 19 causes the combination fluid to be drawn toward screen bore 45 and, thus, into cavity 68 as indicated by arrows 17 and through apertures 48. In so doing, debris within the combination fluid is prevented from flowing through apertures 48 and is captured within cavity 68. The portion of combination fluid that can pass through apertures 48 mixes with the incoming fluid flowing into screen bore 45 from incoming fluid flow accelerator bore 35.

It is to be understood that even though some of the combination fluid mixes with the incoming fluid after the combination fluid passes through apertures 48 of screen member 40, and some of this combination fluid may still contain small debris within it, for simplicity, the resulting mixture of the fluid that has passed through apertures 48 of screen member 40 and fluid that is flowing from tool string bore 16, through bore 35 of fluid flow accelerator 30 continues to be referred to herein as the “incoming fluid.” Thus, the term “incoming fluid” means any fluid flowing downward through bore 35 of fluid flow accelerator 30 or bore 45 of screen member 40 and out of lower end 42 of screen member 40 and “combination fluid” means the mixture of the fluid exiting lower end 42 of screen member 40 with the wellbore fluid.

In the particular embodiment of FIGS. 1-2, outer wall surface 63 of shroud 60 provides a restricted wellbore annulus portion 18. At the top of shroud 60, however, portion 19 of the wellbore annulus is not so limited, i.e., it is larger than portion 18. This arrangement creates a pressure differential that increases the velocity of flow of the combination fluid upward through wellbore annulus portion 18 to facilitate lifting of larger pieces of debris; and decreases the upward velocity of the combination fluid through wellbore annulus portion 19 to facilitate movement of the combination fluid (and debris carried with it) toward screen bore 45 and, thus, into cavity 68.

Circulation of the combination fluid upward can be facilitated by placing tool 20 above a restriction or blockage within wellbore 12. For example, tool 20 can be placed near a bridge plug, packer, or other isolation device. Alternatively, tool 20 can be placed toward the bottom of wellbore 12.

Downhole tool 20 can remain within wellbore 12 until cavity 68 is filled with debris or until all debris within wellbore 12 is captured within cavity 68. Thereafter, downhole tool 20 is removed from wellbore 12 and, in so doing, the debris captured within cavity 68 is also removed.

Referring now to FIG. 3, in another embodiment, two downhole tools 20, each as described with respect to the downhole tools of FIGS. 1-2, are connected to each other within tool string 14. Although downhole tools 20 are shown as being identical to each other, it is to be understood that both downhole tools 20 are not required to be identical to each. To the contrary, one or both of downhole tools 20 can be modified as desired or necessary in accordance with this disclosure and placed within tool string 14.

Moreover, although shown as being connected directly to each other within tool string 14, it is to be understood that the two downhole tools 20 shown in FIG. 3 can disposed within tool string 14 with one or more additional components between them. It is also to be understood that although only two downhole tools 20 are shown in FIG. 3, three or more downhole tools, whether identical to each other, or modified as desired or necessary in accordance with this disclosure, can be disposed in tool string 14, either connected directly to each other or disposed within tool string 14 with one or more other component disposed between one or more of the downhole tools 20.

Placing two downhole tools 20 within tool string 14 permits additional debris to be captured from the wellbore fluid during each downhole run of tool string 14. As shown in FIG. 3, incoming fluid flows down bore 16 of tool string 14, through bore 35 of incoming fluid flow accelerator 30 of the upper downhole tool 20 as indicated by arrow 111. The incoming fluid then exits lower end 42 of screen member 40 of the upper downhole tool 20 and into bore 35 of incoming fluid flow accelerator 30 of the lower downhole tool 20 as indicated by arrow 113. The incoming fluid then exits lower end 42 of screen member 40 of the lower downhole tool 20 and enters wellbore 12.

Upon entering wellbore 12, the incoming fluid mixes with the wellbore fluid, which includes one or more pieces of debris and is carried upward as indicated by arrows 115. As the now combined mixture of incoming fluid and wellbore fluid containing debris (the combination fluid) is transported upward within the wellbore annulus, a first portion of the combination fluid is pulled toward screen bore 45 of screen member 40 of the lower downhole tool 20 as indicated by arrows 116. As a result, the debris within this first portion of combination fluid is blocked from entering screen bore 45 of the lower downhole tool 20 and, thus, is captured within cavity 68 of the shroud 60 of the lower downhole tool 20.

A second portion of the combination fluid continues to flow upward within the wellbore annulus as indicated by arrows 117. This second portion of combination fluid is pulled toward screen bore 45 of screen member 40 of the upper downhole tool 20 as indicated by arrows 118. As a result, the debris within this second portion of combination fluid is blocked from entering screen bore 45 of the upper downhole tool 20 and, thus, is captured within cavity 68 of the shroud 60 of the upper downhole tool 20. As with the embodiments of FIGS. 1-2, the two downhole tools 20 can remain within wellbore 12 until cavities 68 of both downhole tools 20 are filled with debris or until all debris within wellbore 12 is captured within cavities 68. Thereafter, downhole tool 20 is removed from wellbore 12 and, in so doing, the debris captured within cavity 68 is also removed.

Referring now to FIG. 4, downhole tool 120 comprises incoming fluid flow accelerator 130, screen member 40, and shroud 60. Screen member 40 and shroud 60 are unchanged from the various embodiments of screen member 40 and shroud 60 discussed above with respect to the embodiments of FIGS. 1-2. Other than the differences discussed with respect to FIG. 4, incoming fluid flow accelerator 130 has the same structures as incoming fluid flow accelerator 30 of FIGS. 1-2.

As shown in FIG. 4, incoming fluid flow accelerator 130 comprises bore 135 that is in fluid communication with screen bore 45 of screen member in the same manner as the embodiments of FIGS. 1-2, however, incoming fluid flow accelerator 130 further includes one or more wellbore annulus ports 138 that place bore 135 in fluid communication with wellbore annulus portion 19. Ports 138 permit the incoming fluid to exit incoming fluid flow accelerator 130 in the direction of arrows 139 to facilitate directing the combination fluid into cavity 68 of shroud 60. In one specific embodiment, ports 138 are oriented or directed toward opening(s) 66 of FIGS. 1-2. In other words, as shown in FIG. 4, ports 138 are aligned with at least one opening 66. In other embodiments, ports 138 are not aligned with any opening(s) 66, but instead are directed into the wellbore annulus to create a hydraulic barrier that restricts debris laden fluid from flowing upward. By restricting such flow, ports 138 are facilitating the flow of the debris laden fluid into opening(s) 66. In certain embodiment, ports 138 are nozzle jets.

In operation of the specific embodiment of FIG. 4 having ports 138 aligned with one or more opening 66, when the combination fluid reaches the top of shroud 60, the incoming fluid exiting ports 138 directs the combination fluid into cavity 68. Ports 138, therefore, facilitate movement of the combination fluid toward screen member 40. The movement of the combination fluid toward screen member 40 by the incoming fluid exiting ports 138 may be desirable or necessary where a suitable pressure differential is too low or absent between screen bore 45 and wellbore annulus portion 19 such as where apertures 48 are being blocked by debris captured in cavity 68.

Referring now to FIG. 5, in another embodiment, downhole tool 220 comprises incoming fluid flow accelerator 230, screen member 240, shroud 260, and lower sub 270. Lower sub 270 includes bore 275 in fluid communication with screen member bore 245. In the embodiment of FIG. 5, incoming fluid flow accelerator 230 comprises bore 235 having screen port 234 and one or more shroud ports 236. Screen port 234 permits fluid to flow from incoming fluid flow accelerator bore 235 into screen member bore 245. Shroud ports 236 permit fluid to flow from fluid flow accelerator bore 235 into shroud cavity 268. Screen port 234 and shroud ports 236 can have any shape or size desired or necessary to facilitate injection of an incoming fluid from incoming fluid flow accelerator bore 235 into screen member bore 245 and shroud cavity 268, respectively, such that debris can be captured within shroud cavity 268.

In addition to these ports, incoming fluid flow accelerator 230 of the embodiment of FIG. 5 also includes one or more wellbore annulus ports 238 that allow fluid to flow from fluid flow accelerator bore 235 into the wellbore annulus (not shown). Wellbore annulus ports 238 can have any shape or size desired or necessary to facilitate creation of a hydraulic barrier above debris inlet ports 269 to facilitate movement of the combination fluid from the wellbore annulus through debris inlet ports 269 toward screen member 240.

Although the embodiment of FIG. 5 is shown as having screen port 234, shroud ports 236, and wellbore annulus ports 238, it is to be understood that downhole tool 220 is not required to include all of these ports. To the contrary, downhole tool 220 can include only screen port 234, or only one or more shroud ports 236, or only one or more wellbore annulus ports 238, or any combination of these three types of ports.

In the embodiment of FIG. 5, shroud 260 is secured directly to incoming fluid flow accelerator 230 by a fastener such as threads. Disposed through the outer and inner wall surfaces 261, 262, respectively, of shroud 260 are debris inlet ports 269. Lower sub 270 is secured to the lower end of shroud 260 by a fastener such as threads. Although not required to do so, lower sub 270 closes off the lower end of shroud 260 to, along with the inner wall surface of shroud 260 and the outer wall surface of screen 240, define shroud cavity 268.

Downhole tool 220, when placed in a work string, facilitates debris disposed within the wellbore (not shown) to be picked up and flowed upward within the wellbore annulus (not shown) until the combination fluid containing debris flows through debris inlet ports 269. In one particular embodiment, an incoming fluid is flowed downward through the work string and into incoming fluid flow accelerator bore 235. The incoming fluid then exits incoming fluid flow accelerator 230 through screen member port 234 and flows into screen member bore 245. The incoming fluid continues to flow downward until it flows through lower sub bore 275 and into the wellbore, such as through a mill disposed below lower sub 270. The incoming fluid then mixes with the wellbore fluid, which contains debris, to form the combination fluid which flows upward within the wellbore annulus. The combination fluid then enters debris inlet ports 269. The downward flow of the incoming fluid through screen member bore 245 draws the combination fluid toward the screen where the debris is prevented from passing through the screen so that it falls into shroud cavity 268 in a similar manner as discussed above with respect to the embodiments of FIGS. 1-2.

When present, the one or more shroud ports 236 facilitate directing the combination fluid flowing through debris inlet ports 269 toward screen member 240 by, for example, pushing the combination fluid toward apertures 248 after the combination fluid has flowed through debris inlet ports 269.

When present, the one or more wellbore annulus ports 238 facilitate directing the combination fluid flowing through debris inlet ports 269 toward screen member 240 by, for example, creating a hydraulic barrier within the wellbore annulus to prevent the combination fluid to flow upward past debris inlet ports 269.

It is to be understood that the invention is not limited to the exact details of construction, operation, exact materials, or embodiments shown and described, as modifications and equivalents will be apparent to one skilled in the art. For example, the bore of the incoming fluid flow accelerator can have any shape desired or necessary to increase the velocity of the incoming fluid as it passes through the incoming fluid flow accelerator bore. Alternatively, the incoming fluid flow accelerator can use another structure or device, instead of the shape or size of the incoming fluid flow accelerator bore, to increase the velocity of the incoming fluid as it flows through the incoming fluid flow accelerator. Moreover, the incoming fluid flow accelerator is not required to be attached directly to the screen member. Instead, one or more additional components of the work string can be dispose between the incoming fluid flow accelerator and the screen member. Further, the lower portion of the screen bore is not required to have a larger inner diameter compared to an inner diameter of an upper portion of the screen bore. Instead, the upper portion inner diameter can be larger than or equal to the lower portion inner diameter as desired or necessary to facilitate movement of the incoming fluid downward through screen bore and/or to facilitate mixing the incoming fluid with the wellbore fluid and/or lifting the combination fluid upward through the wellbore annulus. Additionally, the apertures in the screen member are not required to be absent above the top of the shroud as shown in FIGS. 1, 3, and 4, but instead can extend above the top of the shroud. In addition, the shroud is not required to be disposed concentrically with the screen member. Instead, it can be disposed eccentrically so that one side has a larger opening compared to another side to facilitate capturing larger sized debris on that side. Nor are the shroud or the screen member both required to have a circular cross-section. Instead, one or both of the shroud or the screen member can have a square or other cross-sectional shape as desired or necessary to facilitate capturing debris within the cavity of the shroud.

Further, it is to be understood that the term “wellbore” as used herein includes open-hole, cased, or any other type of wellbores. In addition, the use of the term “well” is to be understood to have the same meaning as “wellbore.” Moreover, in all of the embodiments discussed herein, upward, toward the surface of the well (not shown), is toward the top of Figures, and downward or downhole (the direction going away from the surface of the well) is toward the bottom of the Figures. However, it is to be understood that the tools may have their positions rotated in either direction any number of degrees. Accordingly, the tools can be used in any number of orientations easily determinable and adaptable to persons of ordinary skill in the art. Accordingly, the invention is therefore to be limited only by the scope of the appended claims. 

What is claimed is:
 1. A downhole tool for capturing debris within a wellbore, the downhole tool comprising: a screen member having a screen upper end, a screen lower end, a screen outer wall surface, a screen inner wall surface defining a screen bore, and at least one screen aperture in fluid communication with the screen inner wall surface and the screen outer wall surface; an incoming fluid flow accelerator disposed above the screen member, the incoming fluid flow accelerator comprising an incoming fluid flow accelerator bore through which an incoming fluid flows toward the screen bore, the incoming fluid flow accelerator bore being in fluid communication with the screen bore such that an incoming fluid flowing out of the incoming fluid flow accelerator bore and into the screen bore creates a pressure differential across at least one of the at least one apertures; and a shroud disposed around a portion of the screen member, the shroud having an opening disposed toward an upper end of the shroud and a closed lower end to define a cavity.
 2. The downhole tool of claim 1, wherein the incoming fluid flow accelerator further comprises at least one port disposed in fluid communication with the incoming fluid flow accelerator bore and oriented to direct a portion of the incoming fluid flowing through the incoming fluid flow accelerator bore toward the opened upper end of the shroud.
 3. The downhole tool of claim 1, wherein the upper end of the shroud comprises a plurality of openings.
 4. The downhole tool of claim 1, wherein screen outer wall surface is concentric with an inner wall surface of the shroud.
 5. The downhole tool of claim 1, wherein the screen outer wall surface defines a screen outer diameter and a shroud inner wall surface defines a shroud inner diameter, the shroud inner diameter being greater than the screen outer diameter to partially define the cavity.
 6. The downhole tool of claim 1, wherein the incoming fluid flow accelerator bore comprises a shape to increase a velocity of an incoming fluid flowing through the incoming fluid flow accelerator bore.
 7. A downhole tool for capturing debris within a wellbore, the downhole tool comprising: a screen member having a screen upper end, a screen lower end, a screen outer wall surface, a screen inner wall surface defining a screen bore, and at least one screen aperture in fluid communication with the screen inner wall surface and the screen outer wall surface; a nozzle assembly disposed above the screen member, the nozzle assembly comprising a nozzle bore shaped to increase a velocity of an incoming fluid flowing through the nozzle bore toward the screen bore, the nozzle bore being in fluid communication with the screen bore; and a shroud disposed around a portion of the screen member, the shroud comprising a shroud upper end, a shroud lower end, a shroud outer wall surface, and a shroud inner wall surface, the shroud upper end having an opening, the shroud lower end being closed, and the shroud inner wall surface, the shroud lower end, and the screen outer wall surface define a cavity within the shroud.
 8. The downhole tool of claim 7, wherein the nozzle bore comprises a variable inner diameter that decreases from an upper end of the nozzle assembly toward a lower end of the nozzle assembly.
 9. The downhole tool of claim 7, wherein the screen member comprises a screen upper end inner diameter that is smaller than a screen lower end inner diameter.
 10. The downhole tool of claim 7, wherein shroud upper end includes a plurality of openings.
 11. The downhole tool of claim 7, wherein the nozzle assembly further comprises at least one secondary nozzle jet in fluid communication with the nozzle bore and oriented to direct the incoming fluid flowing through the nozzle bore toward the opening disposed in the shroud upper end.
 12. The downhole tool of claim 11, wherein at least one of the at least one secondary nozzle jets is directly aligned with at least one of the one or more openings disposed in the shroud upper end.
 13. The downhole tool of claim 7, wherein a lower end of the nozzle assembly is connected to the screen member upper end.
 14. A work string for capturing debris within a wellbore, the downhole tool comprising: a first downhole tool, the first downhole tool comprising a first screen member having a first screen upper end, a first screen lower end, a first screen outer wall surface, a first screen inner wall surface defining a first screen bore, and at least one first screen aperture in fluid communication with the first screen inner wall surface and the first screen outer wall surface; a first incoming fluid flow accelerator disposed above the first screen member, the first incoming fluid flow accelerator comprising a first incoming fluid flow accelerator bore, the first incoming fluid flow accelerator bore being in fluid communication with the first screen bore; and a first shroud disposed around a portion of the first screen member, the first shroud having a first opening disposed toward an upper end of the first shroud and a first closed end to define a first cavity.
 15. The work string of claim 14, further comprising: a second downhole tool, the second downhole tool comprising a second screen member having a second screen upper end, a second screen lower end, a second screen outer wall surface, a second screen inner wall surface defining a second screen bore, and at least one second screen aperture in fluid communication with the second screen inner wall surface and the second screen outer wall surface; a second incoming fluid flow accelerator disposed above the second screen member, the second incoming fluid flow accelerator comprising a second incoming fluid flow accelerator bore, the second incoming fluid flow accelerator bore being in fluid communication with the second screen bore; and a second shroud disposed around a portion of the second screen member, the second shroud having a second opening disposed toward an upper end of the second shroud and a second closed end to define a second cavity, wherein the second incoming fluid flow accelerator bore is in fluid communication with the first screen bore.
 16. The work string of claim 15, wherein the first downhole tool is disposed adjacent the second downhole tool.
 17. A method of removing debris from a wellbore fluid, the method comprising the steps of: (a) flowing an incoming fluid through a screen bore of a screen member and out of a lower end of the screen member into a wellbore environment; (b) after step (a), combining the incoming fluid with a wellbore fluid disposed in the wellbore environment to form a combination fluid, the wellbore fluid comprising a piece of debris; (c) flowing the combination fluid upward within a wellbore annulus; (d) creating a first pressure differential between the screen bore and the wellbore annulus outside the screen member, the first pressure differential causing the combination fluid to be drawn toward the screen member; (e) passing the combination fluid through the screen member causing the piece of debris within the combination fluid to be prevented from passing through the screen, thereby causing the piece of debris to be captured within a cavity formed by a shroud disposed around an outer wall surface of the screen member.
 18. The method of claim 17, wherein the first pressure differential is created by the incoming fluid flowing through a bore of a fluid flow accelerator before entering the screen bore of the screen member, the fluid flow accelerator increasing a first velocity of flow of the incoming fluid to a second velocity of flow.
 19. The method of claim 18, wherein a second pressure differential is created within the wellbore annulus between the upper end of the shroud and an outer wall surface of the shroud, the second pressure differential causing the combination fluid to be drawn toward the screen member.
 20. The method of claim 17, wherein prior to step (d) the combination fluid flows upward within the wellbore annulus and enters an opening at an upper end of the shroud and a portion of the incoming fluid exits the bore of the incoming fluid flow accelerator toward the opening at the upper end of the shroud before entering the screen bore. 